Hydraulic fracturing is a stimulation process for creating high-conductivity communication with a large area of a subterranean formation. The process increases the effective wellbore area within the formation in order that entrapped oil or gas production can be accelerated. The efficiency of the process is often measured by the stimulated reservoir volume (SRV) of the formation.
During hydraulic fracturing, a fracturing fluid is pumped at pressures exceeding the fracture pressure of the targeted reservoir rock in order to create or enlarge fractures within the subterranean formation penetrated by the wellbore. The fluid used to initiate hydraulic fracturing is often referred to as the “pad”. In some instances, the pad may contain fine particulates, such as fine mesh sand, for fluid loss control. In other instances, the pad may contain particulates of larger grain in order to abrade perforations or near-wellbore tortuosity.
Once the fracture is initiated, subsequent stages of fluid containing chemical agents, as well as proppants, may be pumped into the created fracture. The fracture generally continues to grow during pumping and the proppants remain in the fracture in the form of a permeable “pack” that serves to “prop” the fracture open. Once the treatment is completed, the fracture closes onto the proppants. Increasing the fracturing fluid pressure ultimately causes an increase in the leak-off rate of the fluid through the faces of fractures which improves the ability of the proppant to pack within the fracture. Once the treatment is completed, the fracture closes onto the proppants. The proppants maintain the fracture open, providing a highly conductive pathway for hydrocarbons and/or other formation fluids to flow into the wellbore.
The treatment design of a hydraulic fracturing operation for a conventional reservoir generally requires the fracturing fluid to reach maximum viscosity as it enters the fracture. The viscosity of the fluid affects fracture length and width.
The viscosity of most fracturing fluids may be attributable to the presence of a viscosifying agent, such as a viscoelastic surfactant or a viscosifying polymer. An important attribute of any fracturing fluid is its ability to exhibit viscosity reduction after injection. Low viscosity fluids known as slickwater have also been used in the stimulation of low permeability formations, including tight gas shale reservoirs. Such reservoirs often exhibit a complex natural fracture network. Slickwater fluids typically do not contain a viscoelastic surfactant or viscosifying polymer but do contain a sufficient amount of a friction reducing agent to minimize tubular friction pressures. Such fluids, generally, have viscosities only slightly higher than unadulterated fresh water or brine. The presence of the friction reduction agent in slickwater does not typically increase the viscosity of the fluid by more than 1 to 2 centipoise (cP).
To effectively access tight formations, wells are often drilled horizontally and then subjected to one or more fracture treatments to stimulate production. Fractures propagated with low viscosity fluids exhibit smaller fracture widths than those propagated with higher viscosity fluids. In addition, low viscosity fluids facilitate increased fracture complexity in the reservoir during stimulation. This often results in the development of greater created fracture area from which hydrocarbons may flow into higher conductive fracture pathways. Further, such fluids introduce less residual damage into the formation in light of the absence of viscosifying polymer in the fluid.
In some shale formations, an excessively long primary fracture often results perpendicular to the minimum stress orientation. Typically, pumping of additional fracturing fluid into the wellbore simply extends the planar or primary fracture. In most instances, primary fractures dominate and secondary fractures are limited. Fracturing treatments which create predominately long planar fractures are characterized by a low contacted fracture face surface area, i.e., low SRV. Production of hydrocarbons from the fracturing network created by such treatments is limited by the low SRV.
Lately, slickwater fracturing has been used in the treatment of shale formations. However, the secondary fractures created by the operation are near to the wellbore where the surface area is increased. Slickwater fracturing is generally considered to be inefficient in the opening or creation of complex network of fractures farther away from the wellbore. Thus, while SRV is increased in slickwater fracturing, production is high only initially and then drops rapidly to a lower sustained production since there is little access to hydrocarbons far field from the wellbore.
Like slickwater fracturing, conventional fracturing operations typically render an undesirably lengthy primary fracture. While a greater number of secondary fractures may be created farther from the wellbore using viscous fluids versus slickwater, fluid inefficiency, principally exhibited by a reduced number of secondary fractures generated near the wellbore, is common in conventional hydraulic fracturing operations.
Recently, attention has been directed to alternatives for increasing the productivity of hydrocarbons far field from the wellbore as well as near wellbore. Particular attention has been focused on increasing the productivity of low permeability formations, including shale. Methods have been especially tailored to the stimulation of discrete intervals along the horizontal wellbore resulting in perforation clusters. While the SRV of the formation is increased by such methods, potentially productive reservoir areas between the clusters are often not stimulated. This decreases the efficiency of the stimulation operation. Methods of increasing the SRV by increasing the distribution of the area subjected to fracturing have therefore been sought.